Determining fluid leakage volume in pipelines

ABSTRACT

A method and an apparatus for determining leakage volume of fluid in transportation pipelines are provided. The method comprises: obtaining the negative pressure wave signals detected by at least two pressure sensors arranged on the pipeline; determining the pressure signal at the leakage location based on the negative pressure wave signals; determining the leakage rate during a leakage period based on the pressure signal at the leakage location according to a leakage model; and determining the leakage volume of the fluid in the pipeline based on the leakage rate and the leakage period. The apparatus provided corresponds to the method described above. By using the method and apparatus described above, the leakage volume of the transportation pipelines can be obtained to help understand the leakage profile of the pipelines and thus reduce losses ( FIG. 1 ).

TECHNICAL FIELD

The present invention relates to the field of pipeline transportation inindustries, and more particularly, to method and apparatus fordetermining leakage information in pipelines.

DESCRIPTION OF THE RELATED ART

In modern industries, it is often required to transport various kinds offluidic raw materials, such as oil, gas, water, etc, over long distancesvia pipelines. Currently, the total length of the oil and gas pipelinesin the world is 3.5*106 km. The long-distance backbone pipeline in Chinahas exceeded 80,000 km, responsible for the transportation of 70% of oiland 99% of natural gas in China.

However, many of these long distance pipelines have become aged becauseof long service time. For example, in China, the service time of about60% of the long-distance backbone pipelines is over 20 years, and manypipelines have operated for more than 30 years and have moved into aperiod when accidents occurred very often.

Besides the corrosion and aging of pipelines, reasons of leakage furtherinclude changes of the external geography, climate change, and externalvibration. In addition, the more frequent man-made drill for stealingmaterials is also one of the main reasons for pipeline leakage.

It is obvious that pipeline leakage would cause great loss of rawmaterials and great economic loss, and it would also cause environmentalpollution and danger, thus having great harmfulness. In order to reducethe harmfulness to the minimum level, the engineering technicalpersonnel desire to acquire the information relating to leakage, such asleak location and leak time, in the shortest time after the leakagehappens so as to take remedial measures as soon as possible.

For acquiring such leakage information, several solutions have beenadopted in the prior art. In one solution, the fluid flow in thepipelines is detected, and the leakage information is determinedaccording to the flow difference at the two ends of a pipe or the flowchange at a certain end. However, this solution has low sensitivity andhence low accuracy, not satisfying the need of industrial projects. Inanother solution, an optical fibre system is arranged outside pipelines,and the leakage information is determined by the detection of changes ofthe optical fibre signals. Alternatively, a fluid-sensing wire may bearranged, and the leakage information is obtained by the detection ofchanges of conductivity of the fluid. These two solutions have highaccuracy, but require too much project cost, and thus it is difficult toapply on a large-scale basis.

SUMMARY

In view of various factors such as cost and accuracy, one of thepractical solutions is to determine the leakage information of pipelineswith negative pressure wave.

In particular, during the transportation of fluid, the transported fluidexerts a pressure on the wall of pipes. By arranging a number ofpressure sensors along the pipelines, the pressure signals of the fluidmay be detected. Generally, the pressure sensors may be arranged at twoends of a pipe segment. If leak occurs at a location on the pipesegment, the fluid will release some pressure because of the leakage atthe leaking hole, resulting in a decrease of the pressure on thepipelines. The pressure decrease propagates along the pipelines in theform of waves, and is captured by the pressure sensors arranged at theends. As such, the pressure sensors will obtain a decrease of thepressure signal caused by the leakage, which is also referred to asnegative pressure waves. The negative pressure waves can tell us someinformation relating to the leakage of pipelines. In the prior art,however, the analysis to the negative pressure waves is not sufficient,and the obtained leakage information is not complete. The obtainedinformation only includes the approximate time and location of theleakage, and does not include further information such as leakage rateor leakage volume. Thus, it needs to be further improved and enhanced.

In view of the questions existed in the prior art, the present inventionis proposed to provide a method and an apparatus for determining leakagevolume of fluid in pipelines, thereby overcoming at least onedisadvantage of the prior art.

According to one aspect, the invention provides a method for determiningleakage volume of fluid in transportation pipelines, comprising:obtaining the negative pressure wave signals detected by at least twopressure sensors arranged on the pipelines; determining the pressuresignal at the leakage location according to the negative pressure wavesignals; determining the leakage rate during a leakage period based onthe pressure signal at the leakage location according to a leakagemodel; and determining the leakage volume of the fluid in the pipelinesbased on the leakage rate.

According to another aspect, the invention provides an apparatus fordetermining leakage volume of fluid in transportation pipelines,comprising: a signal-obtaining unit, configured to obtain the negativepressure wave signals detected by at least two pressure sensors arrangedon the pipelines; a pressure-determining unit, configured to determinethe pressure signal at the leakage location according to the negativepressure wave signals; a rate-determining unit, configured to determinethe leakage rate during a leakage period based on the pressure signal atthe leakage location according to a leakage model; and avolume-determining unit, configured to determine the leakage volume ofthe fluid in the pipelines based on the leakage rate.

By using the method and apparatus of the invention, we can effectivelyobtain the more detailed leakage information of the pipelines, therebyhelp acquire the leakage profile of the pipelines and reduce costs.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a flow chart showing the method for determining leakage volumeaccording to an embodiment of the invention;

FIG. 2A exemplarily shows negative pressure wave signals from a pressuresensor;

FIG. 2B exemplarily shows the filtered negative pressure wave signals;

FIG. 3 shows the substeps of step 12 according to an embodiment of theinvention;

FIG. 4 exemplarily shows a view of the pressure sensors and the leakagelocation in a typical situation;

FIG. 5 exemplarily shows pressure signals obtained according to anembodiment;

FIG. 6A exemplarily shows pressure signals obtained according to anembodiment;

FIG. 6B shows the slope signals corresponding to the pressure signalsshown in FIG. 6A;

FIG. 6C schematically shows the labeled feature time points and thedivided time segments;

FIG. 7 shows the substeps of step 14 according to an embodiment of theinvention;

FIG. 8A exemplarily shows the average pressure intensity in several timesegments;

FIG. 8B exemplarily shows a query table according to an embodiment;

FIG. 9 shows a block diagram of an apparatus according to an embodimentof the invention; and

FIG. 10 shows a block diagram of an exemplary computing system 100suitable to implement an embodiment of the invention.

DETAILED DESCRIPTION

As will be appreciated by one skilled in the art, aspects of the presentinvention may be embodied as a system, method or computer programproduct. Accordingly, aspects of the invention may take the form of anentirely hardware embodiment, an entirely software embodiment (includingfirmware, resident software, micro-code, etc.) or an embodimentcombining software and hardware aspects that may all generally bereferred to herein as a “circuit,” “module” or “system.” Furthermore,aspects of the invention may take the form of a computer program productembodied in one or more computer readable medium having computer usableprogram code embodied in the medium.

Any combination of one or more computer readable medium may be utilized.The computer readable medium may be computer-readable signal medium orcomputer-readable storage medium. The computer-readable storage mediummay be, for example but not limited to, an electronic, magnetic,optical, electromagnetic, infrared, or semiconductor system, apparatus,device or any combinations thereof. More specific examples (anon-exhaustive list) of the computer-readable storage medium wouldinclude the following: an electrical connection having one or morewires, a portable computer diskette, a hard disk, a random access memory(RAM), a read-only memory (ROM), an erasable programmable read-onlymemory (EPROM or Flash memory), an optical fiber, a portable compactdisc read-only memory (CD-ROM), an optical storage device, a magneticstorage device or any proper combinations thereof. In the context ofthis document, a computer-readable storage medium may be any tangiblemedium that can contain, or store the program for use by or inconnection with the instruction execution system, apparatus, or device.

Computer readable signal medium may include a propagated data signalwith the computer-readable program code embodied therewith, either inbaseband or as part of a carrier wave. Such propagated signal may useany proper form, including but not limited to, electromagnetic signal,optical signal, or any proper combination thereof. Computer readablesignal medium may be any computer readable medium that is different fromcomputer-readable storage medium and can communicate, propagate, ortransport the program for use by or in connection with the instructionexecution system, apparatus, or device.

Program code included in the computer readable medium may be transmittedusing any appropriate medium, including but not limited to wireless,wireline, optical fiber cable, RF, etc. or any proper combinationthereof.

Computer program code for carrying out operations of the presentinvention may be written in any combination of one or more programminglanguages, including an object oriented programming language such asJava, Smalltalk, C++ or the like and conventional procedural programminglanguages, such as “C” programming language or similar programminglanguages. The program code may execute entirely on a user computer,partly on a user computer, as a stand-alone software package, partly onuser computer and partly on a remote computer or entirely on a remotecomputer or server. In the latter scheme, the remote computer may beconnected to the user computer through any type of network, including alocal area network (LAN) or a wide area network (WAN), or the connectionmay be made to an external computer (for example, through the Internetusing an Internet Service Provider).

Below, aspects of the invention will be described with reference toflowchart and/or block diagram of methods, apparatuses (systems) andcomputer program products of the embodiment of the invention. Note that,each block of the flowchart and/or block diagram, and combinations ofblocks in the flowchart and/or block diagram, can be implemented bycomputer program instructions. These computer program instructions maybe provided to a processor of a general-purpose computer, aspecial-purpose computer or other programmable data processing apparatusto produce a machine, such that the instructions which execute on thecomputer or other programmable data processing apparatus create meansfor implementing the functions/actions specified in the block(s) of theflowchart and/or block diagram.

These computer program instructions may also be stored in acomputer-readable medium that can direct a computer or otherprogrammable data processing apparatus to function in a particularmanner, such that the instructions stored in the computer-readablemedium produce an article of manufacture including instruction meanswhich implement the functions/actions specified in the block(s) of theflowchart and/or block diagram.

The computer program instructions may also be loaded into a computer orother programmable data processing apparatus to perform a series ofoperational steps on the computer or other programmable data processingapparatus so as to produce computer implemented process, such that theinstructions which execute on the computer or other programmable dataprocessing apparatus will provide process for implementing thefunctions/actions specified in the block(s) of the flowchart and/orblock diagram.

Next, the embodiments of the invention will be described in conjunctionwith the drawings. It should be appreciated that the description of thefollowing detailed examples are merely to explain the exemplaryimplementing modes, rather than to impose any limitation on scope of theinvention.

In some embodiments of the invention, the negative pressure wavesdetected by pressure sensors are used to determine the leakageinformation of pipelines, including leakage location, leakage time,leakage rate, leakage volume, etc. FIG. 1 is a flow chart showing themethod for determining fluid leakage volume in pipelines according to anembodiment of the invention. As shown in FIG. 1, the method according tothe embodiment comprises: in step 10, obtaining the negative pressurewave signals detected by at least two pressure sensors arranged on thepipelines; in step 12, determining the pressure signal at the leakagelocation according to the negative pressure wave signals; in step 14,determining the leakage rate during a leakage period based on thepressure signal at the leakage location according to a leakage model;and in step 16, determining the leakage volume of the fluid in thepipelines based on the leakage rate and the leakage period.

Specifically, first of all, in step 10, the negative pressure wavesignals detected by pressure sensors are obtained. As described in theDESCRIPTION OF THE RELATED ART section, in order to monitor the pressureof the transported fluid, a plurality of pressure sensors are arrangedin advance on the pipelines. In one case, multiple pressure sensors arearranged along the pipelines at regular intervals. In general cases, foreach whole segment of a straight pipeline, pressure sensors are arrangedat least at both ends of the segment. More particularly, the pressuresensors may be arranged on the valves at the inlet and outlet of thestraight pipeline, thereby detecting the pressure of the transportedfluid.

To determine the leakage information such as the leakage location, theleakage period, etc, it at least needs the negative pressure wavesignals from two pressure sensors. In one embodiment, the two pressuresensors are located at the upstream and downstream of the leakagelocation, respectively. In one particular example, the two pressuresensors are the ones closest to the leakage location at the upstream anddownstream, respectively. It is appreciated, however, that the leakagelocation would be unknown until it is determined with the help of thenegative pressure wave signals. Nevertheless, as the sudden pressuredecrease caused by the leakage would propagate along the pipelines, thetwo sensors closest to the leakage location may be determined accordingto the order and time when the negative pressure waves appear in thepressure signals detected by various pressure sensors.

It is appreciated that the choice of the pressure sensors as describedabove is non-limiting. According to the desired calculation accuracy, aperson skilled in the art may accordingly choose more sensor signals toimprove the calculation accuracy or to verify the calculation results.Alternatively, according to the actual arrangement of sensors, a personskilled in the art may choose two or more sensor signals that are moreaccessible, rather than the sensor signals closest to the leakagelocation. The choice of sensors as described above as well as the choiceof sensors conducted by a person skilled in the art after reading thedisclosure of the specification are encompassed in the scope of theinvention.

On the basis that at least two pressure sensors are determined asdescribed above, the negative pressure wave signals detected thereby maybe obtained. FIG. 2A exemplarily shows negative pressure wave signalsfrom a pressure sensor. As shown in the figure, the pressure signals aremaintained at a relatively high level for a period of time, and decreasesuddenly at a time point, which means the occurrence of leakage.

In one embodiment, the step of obtaining negative pressure wave signalsfurther comprises filtering the read signals. More particularly, theread negative pressure wave signals may be processed by a low passfilter, and thereby the high frequency noise is removed, thus obtainingmuch purer signals. FIG. 2B exemplarily shows the filtered negativepressure wave signals. That is to say, the signals shown in FIG. 2A areprocessed by a low pass filter, thus obtaining the negative pressurewave signals with the high frequency noise removed as shown in FIG. 2B.

On the basis of obtaining the negative pressure wave signals from atleast two pressure sensors, the method according to the embodimentperforms step 12, determining the pressure signal at the leakagelocation according to the obtained negative pressure wave signals. FIG.3 shows the substeps of step 12 according to an embodiment of theinvention. In particular, as shown in FIG. 3, in order to determine thepressure signal at the leakage location, in step 121, it determines theleakage location based on the negative pressure wave signals of the atleast two pressure sensors; and then in step 123, it determines thepressure signal at the leakage location according to the obtainednegative pressure wave signals and the determined leakage location.Next, the above steps will be described in conjunction with a typicalcase as shown in FIG. 4.

FIG. 4 exemplarily shows a view of the pressure sensors and the leakagelocation in a typical situation. In the scenario of FIG. 4, at both endsof a straight pipeline of length L, the pressure sensors A and B arearranged, respectively, which detect pressure signals expressed by PA(t) and PB (t), respectively. Suppose leak occurs at time point t0 andposition P, and distances from P to the pressure sensors A and B are LAand LB, respectively. The pressure change caused by leakage at Ppropagates towards two opposite directions at speed V, and reaches thetwo pressure sensors A and B at time points tA and tB, respectively. Inaddition, suppose the fluid in the pipeline flows from end A to end B atspeed v, then the following formula can be obtained:

L _(A)=(t _(A) − ₀)(V−v)

L _(B)=(t _(B) − ₀)(V+v)  (1)

The following formula can be obtained by eliminating t0 from the abovetwo formulas:

$\begin{matrix}{{t_{A} - \frac{L_{A}}{\left( {V - v} \right)}} = {t_{B} - \frac{L_{B}}{\left( {V + v} \right)}}} & (2)\end{matrix}$

If the relationship L_(A)+L_(B)=L is taken into consideration, thefollowing formula can be obtained:

$\begin{matrix}{{L_{A} = {\left( {V - v} \right)\frac{{\left( {V + v} \right)\left( {t_{A} - t_{B}} \right)} + L}{2\; V}}}{L_{B} = {\left( {V + v} \right)\frac{L - {\left( {t_{A} - t_{B}} \right)\left( {V - v} \right)}}{2\; V}}}} & (3)\end{matrix}$

In the above formulas, LA and LB are dependent on variables tA, tB, Vand v, wherein tA and tB can be obtained by reading the time points whenthe pressure decreases suddenly in pressure signals PA (t) and PB (t) ofthe sensors A and B, V depends on materials of the pipeline and ambienttemperature, v depends on properties of the fluid and exerted pressureintensity, and both V and v can be obtained by measuring or analyzinghistoric data. Hence, distances from leakage position P to sensors A andB, i.e. LA and LB, can be determined by using the above formulas.

Based on the leakage location parameter such determined, in step 123,the pressure signal at leakage position P can be calculated. Inparticular, it may be supposed that the fluid pressure changes linearlyalong the pipeline, that is, the pressure difference between twopositions is proportional to the distance therebetween, and therefore itmay be found that the pressure signal P (t) at leakage position P is:

$\begin{matrix}{{P(t)} = \frac{{{L_{A}}^{*}{P_{A}(t)}} + {{L_{B}}^{*}{P_{B}(t)}}}{L}} & (4)\end{matrix}$

The pressure signal P (t) at leakage position P can be obtained byputting values of LA and LB in formula (3) into formula (4), andcombining the pressure signals PA (t) and PB (t) read from sensors.

In the above embodiment, a process for determining the pressure signalat leakage position according to a particular model is illustrated; itcan be appreciated, however, such embodiment is not limiting. A personskilled in the art may modify the above model, or use other models andhypotheses to determine the pressure signal P (t). For example, in theprocess of determining leakage location, as v<<V is usually true, aperson skilled in the art may omit the items associated with v, andtherefore estimate the leakage position more easily; alternatively, hemay further modify formula (3) by considering other variables associatedwith the propagation of negative pressure waves. In the process ofdetermining the pressure signal P (t) based on the leakage location, aperson skilled in the art may further modify the linear model byconsidering the distribution of the pressure waves along the pipeline,and therefore calculate the pressure signals more accurately.

On the basis of obtaining the pressure signal P (t) at leakage position,the pressure signal may be further analyzed to determine additionalleakage information, as shown in steps 14 and 16 of FIG. 1.

FIG. 5 exemplarily shows pressure signals obtained according to anembodiment. In one embodiment, the fluid leakage rate and volume underthe pressure signal P (t) of FIG. 5 are determined by using a simpleproportional leakage model. In particular, in one example, in step 14,according to a proportional leakage model, it can be approximatelydeemed that the fluid leakage rate I after the leak begins isproportional to the stable pressure intensity P, that is, I=λP, whereinP is the stable pressure intensity before the leak begins, λ is aproportionality factor, which depends on properties of the fluid and canbe obtained empirically from historic data. Subsequently, in step 16,the leakage volume may be approximately estimated as the product of theabove leakage rate I and the leakage period:

M=I(t−t ₀)=λP(t−t ₀)  (5)

By the above formula, the estimation of the fluid leakage volume M inpipelines can be obtained.

In another example, the leakage rate and volume are estimated by using amodified proportional model. In particular, in step 14, in the modifiedproportional model, it can be deemed that the fluid leakage rate i isproportional to the pressure intensity P (t) at each time point, i.e.I=λP(t), wherein λ, is also a proportionality factor, but P (t) is thepressure intensity at time point t during the leak process. Therefore,the leakage rate is a variable changing with time, instead of aconstant. As such, in step 16, the leakage volume can be estimated asthe integral of leakage rate and time:

$\begin{matrix}{M = {\int_{t_{0}}^{t}{\lambda \; {P(t)}\ {t}}}} & (6)\end{matrix}$

By the above formula, the fluid leakage volume M in pipelines isdetermined by the modified proportional model.

However, the actual leak process of fluid may be much more complex.During the leak process, the negative pressure waves propagate along thepipeline, reflect at the end of the pipeline, and are superposed withthe initial waves, such that the detected negative pressure wavesignals, and therefore the pressure signal P (t) at leakage locationdetermined based thereon, fluctuate repeatedly. Furthermore, it usuallytakes several hours to fix the leakage point after the leak begins.During such a long time period, the pressure signal P (t) may sometimesbe unstable due to various external factors, such as geological factors,human factors, etc. On the other hand, in many transportation pipelines,automatic pressure devices are arranged. Once it is found that the fluidpressure is not high enough, an automatic pump will be triggered topressurize the fluid, thereby ensuring the transportation of the fluid.In this case, if the sudden pressure decrease caused by leakage triggersthe above automatic pump, the pressurization of the automatic pump willin turn bring more complex influences and changes to the pressure signalP (t) at leakage location. FIG. 6A exemplarily shows pressure signalsobtained according to an embodiment. It can be seen that, as comparedwith FIG. 5, the pressure signal P (t) shown in FIG. 6A has repeatedfluctuation and more complex changes. As such, in steps 14 and 16, morerefined leakage models may be used to determine leakage information.

FIG. 7 shows the substeps of step 14 according to an embodiment of theinvention. In the embodiment as shown in FIG. 7, step 14 of determiningthe leakage rate during a leakage period may be carried out by thefollowing substeps: first in step 141, obtaining the slope informationof the pressure signal P (t) at leakage location over time; then in step143, according to the slope information, dividing the leakage periodinto a plurality of time segments; and in step 145, according to theleakage model, determining the leakage rate in each time segment.

In particular, for the pressure signal P (t) as shown in FIG. 6A, instep 141, it can calculate the change rate of the pressure signal overtime, i.e. the slope information. FIG. 6B shows the slope signals thusobtained corresponding to the pressure signals shown in FIG. 6A.

Based on the obtained slope signals, the characteristic time points whensudden pressure changes occur may be labeled. In one example, in step143, it compares the slope signals with a predetermined threshold, findsthe slope points where the absolute values of the slope are larger thanor equal to the predetermined threshold, and determines the time pointscorresponding to these slope points. Thus determined time pointscorrespond to the characteristic time points when sudden pressurechanges occur. By using these characteristic time points, the leakageperiod can be divided into a plurality of time segments.

FIG. 6C schematically shows the labeled characteristic time points andthe divided time segments. In accordance with the method describedabove, based on the slope information of FIG. 6B, a series ofcharacteristic time points t0, t1, t2 . . . can be determined;accordingly, these time points constitute a plurality of successive timesegments S0, S1, S2, S3, wherein S1=[ti−1, ti], S0=[t0−δ, t0], and δ maybe a predetermined value. By dividing the leakage period into aplurality of time segments, it can be seen that the pressure isrelatively stable within each time segment. Thus, it can more accuratelydetermine the leakage rate and volume within each time segment.

Hence, in step 145, according to the leakage model, the leakage rate ofthe stable fluid within each time segment is determined For the stablefluid, there are many leakage models for estimating the leakage rate andvolume. The precision and complexity of evaluation would be differentfor different models. Detailed procedure for estimating leakage rate inseveral models will next be illustrated exemplarily.

In one leakage model, it is considered that the leakage rate is relatedto the pressure intensity ratio within a time segment. In particular,suppose that P0 is the average pressure intensity before the leakbegins, P1 is the average stable pressure intensity within the firsttime segment after the leak begins, Pi is the average stable pressureintensity within the i'th time segment. Because of the sudden pressuredecrease caused by the leakage, P0>P1. However, after the leak begins,due to automatic pressurization or other factors, it is possible thatthe pressure intensity increases as compared with P1, that is, it ispossible that the pressure intensity within the i'th time segment (i>1)is larger than P1. FIG. 8A exemplarily shows the average pressureintensity in several time segments. In the pressure intensity ratiomodel, it can be considered that the leakage rate in the first timesegment is:

flow1=max{P0/P1−1,0}*flow  (7a)

wherein flow is a variable associated with properties of the fluid andcan be obtained empirically from historic data. In the subsequent i'thtime segment, the leakage rate is considered as:

flowi=flow1*Pi/P1  (7b)

By the above formulas (7a) and (7b), the leakage rate in each timesegment can be determined.

The above model can be modified by further considering additionalvariables so as to obtain more accurate estimation of the leakage rate.In particular, a fluid function f (T, flow_type) may be introduced,which function is associated with the temperature T and the type of thefluid. On this basis, it can be deemed that the fluid leakage rate inthe i'th time segment is:

flowi=f(T,flow_type)*max{P0/P1−1,0}*(Pi)^(β)  (8)

wherein, β is determined by historic data. Thus, the leakage rate withineach time segment can be obtained.

In another leakage model, a query table is obtained by studying historicdata and is used to indicate the fluid leakage pattern under variouspressures. When estimating the fluid leakage rate, various parametersassociated with the leakage rate can be determined by referring to thequery table. FIG. 8B exemplarily shows a query table according to anembodiment. In the embodiment associated with FIG. 8B, the leakage ratein the first time segment is expressed as (9a), and the leakage rate inthe subsequent i'th time segment is expressed as (9b):

flow1=a*flow  (9a)

flowi=flow1*b  (9b)

wherein the proportionality factors a and b are determined by the querytable shown in FIG. 8B. In particular, in the process of determining theproportionality factor a, the ratio of the stable pressure intensity P1in the first time segment to the stable pressure intensity P0 before theleak begins is considered, and the value of a is determined based on therange to which the above ratio belongs. In the process of determiningproportionality factor b, the ratio interval of the stable pressureintensity Pi in the i'th time segment to the P1 is considered todetermine the value of b. Based on the determined proportionalityfactors a and b, the leakage rate in each time segment can bedetermined.

In the above, the examples of determining leakage rates in various timesegments according to particular leakage models are illustrated inseveral embodiments; it can be understood, however, that these examplesare not limiting. A person skilled in the art may modify the aboveleakage models, or use other leakage models and hypotheses to determinethe leakage rate within a particular time segment.

On the basis of determining the leakage rate in each time segment, theleakage volume during a time period can be determined, that is, step 16in FIG. 1 is carried out. In particular, if the time period from theleakage starting time t0 to current time t is divided into n timesegments, wherein the fluid leakage rate in the i'th time segment Si isdetermined as flowi, the leaked fluid volume from t0 to the current timeis:

$\begin{matrix}{M = {{\sum\limits_{i = 1}^{n}\; {{flowi}^{\;*}S_{i}}} = {\sum\limits_{i = 1}^{n}\; {{flowi}^{\;*}\left( {t_{i} - t_{i - 1}} \right)}}}} & (10)\end{matrix}$

In the examples described above, the total leakage volume is obtained bydividing the leakage period into a plurality of time segments,determining the leakage rate in each time segment, and then summatingleakage volumes in all time segments.

It can be seen that, in the process of determining the leakage volume,the method according to the embodiments of the invention mayadditionally determine many pieces of leakage-related information, suchas leakage location, leakage time (period), the pressure signal at theleakage location, leakage rate, etc. This information may also be usedin other applications for further analyzing the leakage.

In steps 10 to 16 of FIG. 1, many models are used, including, forexample, models for selecting pressure sensors, models for determiningthe pressure signal at the leakage location, leakage models fordetermining the leakage rate in a particular time segment, and the like.These models may be selected by a person skilled in the art based ontheir experiences and requirements, and be applied in variousembodiments of the invention. Alternatively, in one embodiment, theappropriate models may be selected or provided by users. In particular,in one example, the method according to an embodiment of the inventionfurther comprises the step of providing a model library and the step ofreceiving model selection, wherein in the step of providing a modellibrary, it integrates various models that may possibly be used into amodel library, provides it to users via an appropriate interface, andprovides the options of models to users; in the step of receiving modelselection, it receives the selection of models made by users via theinterface. Hence, the variables associated with the leakage informationcan be determined based on the models selected by users. In anotherexample, the models may also be provided or defined by users. In thiscase, the method according to an embodiment of the invention maycomprise the step of receiving model definition, for receiving thedefinition of models made by users. In particular, in this step, auser-interactive interface may be provided, such that users may specifyleakage models by inputting the definition of models via the interface,for example, inputting a definitive formula similar to formula (8).Thus, models specified or defined by users may be used to determine theleakage information. It can be understood that the model-determiningmodes in the examples described above may be combined to provide moreflexible implementing modes. That is, according to an embodiment, amongvarious models to be used, some models may be predetermined by thesystem, some models may be selected from the model library by users, andother models may be directly defined by users. Correspondingly, theembodiment selectively comprises the step of providing a model library,the step of receiving model selection, the step of receiving modeldefinition, etc, as described above.

By using the method according to the embodiments described above, thedesired leakage information, including leakage location, leakage rateand leakage volume, may be obtained using several models based on thenegative pressure wave signals detected by the pressure sensors onpipelines. These pieces of information help researchers and engineersknow the leakage profile quickly, and take appropriate measures in time,thus reducing the cost caused by the leakage to the minimum level.

Based on the same inventive concept, the invention further provides anapparatus for determining leakage volume of fluid in a pipeline. FIG. 9shows a block diagram of an apparatus according to an embodiment of theinvention. As shown in FIG. 9, the apparatus 900 according to theembodiment comprises: a signal-obtaining unit 90, configured to obtainthe negative pressure wave signals detected by at least two pressuresensors arranged on the pipelines; a pressure-determining unit 92,configured to determine the pressure signal at the leakage locationbased on the negative pressure wave signals; a rate-determining unit 94,configured to determine the leakage rate during a leakage period basedon the pressure signal at the leakage location according to a leakagemodel; and a volume-determining unit 96, configured to determine theleakage volume of the fluid in the pipeline based on the leakage rateand leakage period.

In particular, to determine the leakage information, thesignal-obtaining unit 90 at least needs to obtain the negative pressurewave signals from two pressure sensors. In one embodiment, the twopressure sensors are located at the upstream and downstream of theleakage location, respectively. More particularly, the two pressuresensors are the ones closest to the leakage location at the upstream anddownstream, respectively. It can be understood, however, that accordingto the desired calculation accuracy, a person skilled in the art mayaccordingly choose more sensor signals to improve the calculationaccuracy or to verify the calculation results; or alternatively,according to the actual arrangement of sensors, a person skilled in theart may choose two or more sensor signals that are more accessible.

In one embodiment, the signal-obtaining unit 90 is further configured tofilter the read negative pressure wave signals, for example, by a lowpass filter, such that the high frequency noise is removed, thusobtaining much purer signals.

On the basis that the signal-obtaining unit 90 has obtained the negativepressure wave signals from at least two pressure sensors, thepressure-determining unit 92 determines the pressure signal at theleakage location based on the obtained negative pressure wave signals.More particularly, the pressure-determining unit 92 may comprise thefollowing submodules: a location-determining module, configured todetermine the leakage location based on the negative pressure wavesignals of the at least two pressure sensors; and a pressure-determiningmodule, configured to determine the pressure signal at the leakagelocation according to the obtained negative pressure wave signals andthe determined leakage location.

In one embodiment, the location-determining module obtains the leakagelocation by calculation based on the time points to and tB when thesudden pressure decrease occurs in the sensor pressure signals, thenegative pressure wave propagation speed V, and the fluid transportationspeed v. Based on the leakage location thus determined, thepressure-determining module determines the pressure signal P (t) at theleakage location according to a linear pressure intensity model. It canbe understood, however, that the linear pressure intensity model is onlyexemplary but not limiting. A person skilled in the art may modify themodel, or use other models and hypotheses to determine the pressuresignal P (t).

On the basis of obtaining the pressure signal P (t) at the leakageposition, the rate-determining unit 94 and the volume-determining unit96 analyze the signal and thereby determine additional leakageinformation.

In one example, the rate-determining unit 94 determines the fluidleakage rate under the pressure signal P (t) by using a proportionalleakage model; then the volume-determining unit 96 determines the fluidleakage volume during a time period. In another example, therate-determining unit 94 and the volume-determining unit 96 modify thesimple proportional leakage model by considering changes of the leakagerate with time and changes of pressure intensity, and use the modifiedmodel to estimate the leakage rate and volume.

In one embodiment, in order to analyze more complex pressure signals,the rate-determining unit 94 divides the pressure signal based on timesegments, and determines the leakage rate within each time segment. Inparticular, the rate-determining unit 94 may comprise the followingsubmodules: a slope-determining module, configured to obtain the slopeinformation of the pressure signal P (t) at leakage location over time;a time-segment-dividing module, configured to divide the leakage periodinto a plurality of time segments according to the slope information;and a rate-determining module, configured to determine the leakage ratein each time segment according to the leakage model. In one leakagemodel, the rate-determining module deems that the leakage rate in a timesegment is associated with the pressure intensity ratio, therebyobtaining the leakage rate in each time segment. The above model can bemodified by further considering additional variables, for example, byintroducing a fluid function f (T, flow_type), so as to obtain moreaccurate estimation of the leakage rate. In another leakage model, aquery table is used to indicate the fluid leakage pattern under variouspressures. When estimating the fluid leakage rate, the rate-determiningmodule determines various parameters associated with the leakage rate byreferring to the query table. It can be understood, however, that theleakage models described above are only exemplary but not limiting. Aperson skilled in the art may modify the above leakage models, or useother leakage models and hypotheses to determine the leakage rate withina particular time segment.

On the basis of determining the leakage rate in each time segment, thevolume-determining unit 96 may obtain the total leakage volume during atime period by summating the leakage volumes in all time segments.

It can be seen that, in order to determine the desired leakageinformation, the units mentioned above use various models, respectively.These models may be loaded into the apparatus 900 in advance, or beselected or defined by users. To this end, in one embodiment, theapparatus 900 further comprises a model library-providing unit and amodel selection-receiving unit (not shown), wherein the modellibrary-providing unit is configured to provide users with a modellibrary comprising various models via an appropriate interface, andprovide options of models; and the model selection-receiving unit isconfigured to receive the selection of models made by users via theinterface. In another example, the apparatus 900 may comprise a modeldefinition-receiving unit (not shown), configured to receive thedefinition of models made by users. It can be understood that theapparatus 900 may selectively comprise a part or all of the modellibrary-providing unit, the model selection-receiving unit and the modeldefinition-receiving unit as described above.

The implementing principle and mode of the apparatus shown in FIG. 9will not be detailed as they correspond to those of the method shown inFIG. 1. By using the method and apparatus described above, the leakageinformation of the transportation pipelines can be obtained to helpunderstand the leakage profile of the pipelines and thus reduce losses.

FIG. 10 shows a block diagram of an illustrative computing system 100adapted to implement embodiments of the invention. As shown, thecomputer system 100 may comprise: a CPU (Central Processing Unit) 101, aRAM (Random Access Memory) 102, a ROM (Read-Only Memory) 103, a systembus 104, a hard disk controller 105, a keyboard controller 106, a serialinterface controller 107, a parallel interface controller 108, a displaycontroller 109, a hard disk 110, a keyboard 111, a serial externaldevice 112, a parallel external device 113 and a display 114. Amongthese devices, the system bus 104 couples to the CPU 101, the RAM 102,the ROM 103, the hard disk controller 105, the keyboard controller 106,the serial controller 107, the parallel controller 108 and the displaycontroller 109. The hard disk is coupled to the hard disk controller105, the keyboard 111 is coupled to the keyboard controller 106, theserial external device 112 is coupled to the serial interface controller107, the parallel external device 113 is coupled to the parallelinterface controller 108, and the display 114 is coupled to the displaycontroller 109. It is appreciated that, the structural block diagramshown in FIG. 10 is merely for purpose of illustration, rather thanbeing a limitation to the scope of the invention. In some circumstances,certain devices may be added or removed based on actual condition.

The flowcharts and block diagrams in the accompany drawing illustratethe architecture, functionality, and operation of possibleimplementations of systems, methods and computer program productsaccording to various embodiments of the present invention. In thisregard, each block in the flowcharts or block diagrams may represent amodule, segment, or portion of code, which comprises one or moreexecutable instructions for implementing the specified logicalfunction(s). It should also be noted that, in some alternativeimplementations, the functions noted in the block may occur out of theorder noted in the figures. For example, two blocks shown in successionmay, in fact, be executed substantially concurrently, or the blocks maysometimes be executed in the reverse order, depending upon thefunctionality involved. It will also be noted that each block of theblock diagrams and/or flowchart illustration, and combinations of blocksin the block diagrams and/or flowchart illustration, can be implementedby special purpose hardware-based systems that perform the specifiedfunctions or acts, or combinations of special purpose hardware andcomputer instructions.

Although respective apparatus and method of the present invention havebeen described in detail in conjunction with specific embodiments, thepresent invention is not limited thereto. Under teaching of thespecification, various changes, replacements and modifications may bemade to the invention by those skilled in the art without departing fromthe spirit and scope of the invention. It is appreciated that, all suchchanges, replacements and modifications still fall within the protectionscope of the invention. The scope of the invention is defined by theappended claims.

What is claimed is:
 1. A computer program product comprising anon-transitory computer readable storage medium having a computerreadable program stored thereon, wherein the computer readable program,when executed by a processor, causes the processor to: obtain negativepressure wave signals detected by at least two pressure sensors arrangedon the pipeline; wherein the at least two pressure sensors are arrangedon the pipeline such that, for each whole straight segment of thepipeline, one or more pressure sensors of the at least two pressuresensors are arranged at least at each end of the respective wholestraight segment of the pipeline; determine a pressure signal at aleakage location based on the negative pressure wave signals; determinea leakage rate during a leakage period based on the pressure signal atthe leakage location according to a leakage model; and determine theleakage volume of the fluid in the pipeline based on the leakage rateand the leakage period.
 2. The computer program product according toclaim 1, wherein the at least two pressure sensors comprises the twopressure sensors closest to the leakage location.
 3. The computerprogram product according to claim 1, wherein the program instructionsare further configured to cause the processor to obtain the negativepressure wave signals by processing the read negative pressure wavesignals by a low pass filter.
 4. The computer program product accordingto claim 1, wherein the program instructions are further configured tocause the processor to determine the pressure signal at the leakagelocation by: determining the leakage location based on the negativepressure wave signals; and determining the pressure signal at theleakage location according to the obtained negative pressure wavesignals and the determined leakage location.
 5. The computer programproduct according to claim 4, wherein determining the pressure signal atthe leakage location according to the obtained negative pressure wavesignals and the determined leakage location comprises: deducing thepressure signal at the leakage location by using a linear model in whichthe fluid pressure changes linearly along the pipeline, based on thenegative pressure waves signals at the at least two pressure sensors,and the distances from the leakage location to the at least two pressuresensors.
 6. The computer program product according to claim 1, whereinthe program instructions are further configured to cause the processorto determine the leakage rate during a leakage period by determining theleakage rate as being proportional to the pressure intensity at theleakage location according to a proportional leakage model.
 7. Thecomputer program product according to claim 1, wherein the programinstructions are further configured to cause the processor to determinethe leakage rate during a leakage period by: obtaining the slopeinformation of the pressure signal at the leakage location over time;dividing the leakage period into a plurality of time segments accordingto the slope information; and determining the leakage rate in each timesegment according to the leakage model.
 8. The computer program productaccording to claim 7, wherein determining the leakage rate in each timesegment comprises selecting from a group comprising at least one of:determining the leakage rate according to the ratio of the stablepressure intensity in each time segment to a particular pressureintensity; estimating the leakage rate according to the stable pressureintensity in each time segment and a fluid function; and determining theleakage rate by referring to a query table.
 9. The computer programproduct according to claim 7, wherein determining the leakage volume ofthe fluid in the pipeline based on the leakage rate comprises: summatingthe leakage volumes in each time segment; and obtaining the totalleakage volume during the leakage period.
 10. The computer programproduct according to claim 1, wherein the program instructions arefurther configured to cause the processor to: provide users with a modellibrary comprising various leakage models and options of leakage modelsvia an appropriate interface; and receive the selection of leakagemodels made by users via the interface.
 11. The computer program productaccording to claim 1, the program instructions are further configured tocause the processor to receive the definition of leakage models made byusers.